Wellbore fluids

ABSTRACT

Wellbore fluids are disclosed which comprise liquid dispersions of particulate mixed divalent metal carbonates having a generally platy crystal form. Mixed alkaline earth metal carbonates are preferred. The invention further relates to a method of well construction, well remediation, or stimulation utilizing such wellbore fluids.

This application is a 371 application of PCT/EP 95/03579 filed Sep. 12,1995.

This invention relates to wellbore fluids suitable for use in the oiland gas exploration and production industries and embraces fluids usedfor drilling, completion, cementing, workover or packing of wellbores,and includes so called "spacer fluids" and "spotting fluids" whosefunctions are, respectively, to separate dissimilar fluids duringpumping operations, and to spot or treat certain intervals of thewellbore. The term "wellbore fluid" also embraces so-called "fracturingfluids" which are pumped at a pressure sufficient to fracture the rockforming the producing reservoir.

During well construction, there are many occasions when it is necessaryto pump wellbore fluids which are viscosified in order to, for example,remove debris such as cuttings from a well, or which are gelledsufficiently to suspend quantities of powdered dense minerals such asbarytes.

It is also frequently important that the slurries forming the wellborefluids do not leak-off or filter into permeable formations at a highrate. For instance during drilling, high filtration rate fluids mayproduce a thick filter cake leading to sticking of the drill string.Equally the invasion of large quantities of filtrate may damage thepermeability of reservoir rocks causing reduced hydrocarbon production.If cement slurries filter too readily, premature solidification of thecement may occur during the pumping operation. Fracturing operations areless efficient if the fracturing fluid "leaks-off" into porous rock,losing the pressure required to fracture further.

Whilst many soluble polymers have been developed to provide viscosityand filtration control, it is frequently desirable to combine thesewith, or use alone, finely divided minerals to enhance or achieve theabove properties.

According to a first aspect of the invention, there is provided awellbore fluid comprising a liquid dispersion of a particulate mixeddivalent metal carbonate which has a generally platy crystal form.

Where the wellbore fluid is two phase, for example an emulsion wellborefluid having oily and a water phases, the particulate carbonate may bedispersed or mixed in either or both of the phases.

Preferred mixed divalent metal carbonates are the mixed alkaline earthmetal carbonates, and presently the most preferred of these is huntite.

Huntite is a carbonate of calcium and magnesium of the general formulaCaMg₃ (CO₃)₄. It occurs in nature in the USA and Greece as compactmasses of very small crystals of the order of 1 micron and the crystalsare generally platy in nature. The chalk-like material as mined isreadily milled, and the mineral easily disperses to discrete crystals onshearing in water.

The particulate mixed metal carbonate, such as huntite, shouldpreferably have an aspect ratio of at least 5 and will typically have aparticle size distribution such that a high proportion, such as 90% ormore, of the particles have an equivalent spherical diameter (esd) inthe range of from 0.1-5 microns.

The invention is not restricted to mixed metal carbonates, such ashuntite, obtained from natural deposits. Synthetic huntite or othersynthetic mixed metal carbonates obtained by precipitation from aqueoussolutions may be a potential alternative source.

In the wellbore fluid of the invention, the mineral particles may bedispersed or mixed in any liquid phase, suitable for a wellbore fluidssuch as, for example, fresh water, sea water, brines of water solublesalts, oily liquids such as petroleum oils and derivatives, esters,ethers, mono alphaolefins, polyalphaolefins, acetals, and emulsions.

It has surprisingly been found that mixed metal carbonates having agenerally platy crystal character, such as huntite (natural orsynthetic) will confer the advantageous properties of increasedviscosity and gelation, and of reduced filtration rate, when mixed intothe liquid phase.

Unlike bentonite which will only develop viscosity and filtrationcontrol in relatively fresh water, platy mixed metal carbonates such ashuntite are effective by direct mixing into brines such as solutions ofthe halides of the alkali metal of alkaline earth metal groups, formatesof the alkali metal group, and potassium carbonate. Particularlyadvantageous results have been obtained using brines of formates of thealkali metal group, such as potassium formate; these give good resultswhen the mixed metal carbonate is huntite.

Unlike attapulgite and asbestos, whose fibrous nature presents a healthhazard by dust inhalation, huntite is of low risk, and its filtrationcontrol effect is superior.

Another significant advantage of platy mixed metal carbonates such ashuntite over the clay minerals is that they may readily be dissolved inacids, allowing simple removal by acidisation of residual huntite solidswhich may temporarily plug channels such as perforations in an oil orgas producing formation.

Other additives which may be contained in the wellbore fluid of theinvention include, but are not limited to: cement, water solublepolymers such as xanthan gum, hydroxyethylcellulose and other cellulosederivatives, guar gum and derivatives such as hydroxypropyl guar,pregelatinised starch and derivatives such as carboxymethylstarch;synthetic polymers such as polyacrylamides, polyacrylates, andcopolymers of sulphonated ethylenically unsaturated monomers with othervinyl monomers. Emulsifiers and wetting agents may be added whenrequired. Density increasing agents such as powdered barytes, hematiteor calcium carbonate may be incorporated. The wellbore fluid may containother additives known to those skilled in the art.

The dose of the mixed metal carbonate, such as huntite, in the wellborefluid is preferably at least about 3.5 lbs per barrel (10 kg/m³). Thepreferred upper limit for the amount of huntite in the wellbore fluid isabout 140 lbs per barrel (400 kg/m³).

Optionally, for applications in wellbore fluids comprising an oilycontinuous liquid phase, the mixed metal carbonate, such as huntite, maybe treated prior to use with an agent rendering the surface of thehuntite particles at least partially hydrophobic. The hydrophobisingagent may be an agent having one or more non-polar portions (such as analkyl chain or chains, each of which has from, for example, 10 to 30carbon atoms) and a suitable polar portion, and may, for example, beselected from the group including, but not being limited to:

fatty acids such as stearic or palmitic acid and their soaps;

phosphate esters of alcohols or alcohol ethoxylates possessing asufficiently large alkyl chain to provide the hydrophobising effect, andtheir salts; and

alkyl sulphonates or alkylaryl sulphonates and their salts.

The pretreatment may, for instance, consist of the addition ofsufficient of the hydrophobising agent to a slurry of the mixed metalcarbonate, followed by filtration, drying and milling. Alternatively,the filtration and subsequent steps may be omitted, the slurry ofhydrophobised huntite being added directly to the wellbore fluid. Thislatter process may be performed at the well site.

According to a second aspect of the invention, there is provided amethod of well construction, well remediation or stimulation wherein awellbore fluid according to the first aspect of this invention isemployed.

After the operation is completed, the well may be directly prepared forproduction. Alternatively an acidic solution such as hydrochloric acidmay be introduced to the well whereupon residual mineral solids, such asthe filter cake deposited during the method, are dissolved by the acidcausing the opening of flow channels in the reservoir interval, andallowing increased production of hydrocarbons, or increased injection offluids in the case of an injection well.

The invention will now be illustrated by reference to the followingexamples. In these examples, the wellbore fluid properties were testedin accordance with API (American Petroleum Institute) RP 13B-2 1990.

The following abbreviations are used:

PV The plastic viscosity of a drilling fluid (centipoise). Generally lowPV is advantageous.

AV The apparent viscosity of a drilling fluid (centipoise).

YP The yield point (lbs/100 ft²) of the fluid and is a measure of thenon Newtonian viscous characteristics.

6 rpm & 3 rpm Dial readings on the Fann Viscometer which indicate theviscosity at low shear rates. Higher 6 rpm, and 3 rpm values indicategreater thixotropy which is generally advantageous.

Gels A measure of the gelling and suspending characteristics of thefluid (lbs/100 ft²), determined using the Fann viscometer.

API FL API room temperature fluid loss. A measure of the ease offiltering a drilling fluid through a filter paper at 100 psidifferential pressure. Results in milliliters of filtrate. Low filtratevolumes are advantageous.

EXAMPLE 1

An aqueous potassium formate (75% w/w) brine exhibited a specificgravity of 1.57. Its viscosity and filtration properties were measured.

To 522 grams of the potassium formate solution was added 45 grams ofpowdered huntite. The suspension was mixed for ten minutes using aSilverson high shear mixer. The resulting viscous slurry exhibited aspecific gravity of 1.62. Its viscosity was measured prior to dynamicheat ageing (BHR) of the fluid in a rolling pressurised cell for sixteenhours at 142° C. (288° F.), whereupon (AHR), its viscosity andfiltration properties were determined. The results obtained aredisplayed in Table 1.

The results show the ready development of very advantageous viscousproperties by the simple mixing of huntite into a dense potassiumformate brine. Good rheological properties are maintained after exposureto a high temperature (142° C.). Surprisingly, the huntite confers aeight-hundred-fold reduction in filtration rate.

                  TABLE 1    ______________________________________           PV   YP     6 rpm   3 rpm Gels  API FL    ______________________________________    75% Potassium             2      0      0     0     0/0   200 ml in 5    Formate Brine                            sec    Brine + 45 g             18     64     18    18     8/10 --    Huntite BHR    Brine + 45 g             40     80     19    16    10/12 90 ml in 30    Huntite AHR                              min.    ______________________________________

EXAMPLE 2

A sodium chloride brine of specific gravity 1.14 was viscosified withIDHEC (mark of Schlumberger) hydroxyethylcellulose according to thefollowing formulation which produces 350 ml of fluid:

    ______________________________________           Water           324.5 g           Sodium Chloride 73.8 g           IDHEC           1.0 g    ______________________________________

A similar formulation was mixed to include powdered huntite according tothe following formulation (also to 350

    ______________________________________           Water           307.8 g           Sodium Chloride 70.0 g           IDHEC           1.0 g           Huntite         45.0 g    ______________________________________

The rheological and filtration properties of both fluids were measuredand are displayed in Table 2. The results show that huntite imparts avery advantageous increase in yield point and, in particular, in the lowshear rate viscosity and gels of the fluid. This particularly improvesthe suspending ability of the fluid and its ability to carry cuttings,suspended larger particles, or debris in a wellbore pumping operation.

The huntite has conferred a very advantageous reduction in filtrationrate by a factor of one thousand two hundred.

                  TABLE 2    ______________________________________    PV         YP     6 rpm   3 rpm Gels  API FL    ______________________________________    Brine + 11     10     1     1     1/1   180 ml in 15    IDHEC                                   sec.    Brine + 30     85     35    30    23/25 18 ml in 30    IDHEC +                                 min.    Huntite    ______________________________________

EXAMPLE 3

The filter cake from the filtration test in Example 2 was placed in abeaker and covered with 15 percent hydrochloric acid. Rapid and completedissolution of the cake occurred. This illustrates the advantage thatresidual wellbore fluid of the present invention, and its filter cakesmay readily be removed from a wellbore by conventional acid pumpingoperations.

EXAMPLE 4

A guar gum base solution such as may be used in well-fracturingoperations was prepared to the following formulation.

    ______________________________________    Water                    1 liter    Potassium Chloride       20 g    F75N ™ Fluorosurfactant                             1 ml    Guar Gum                 3.6 g    ______________________________________

A similar formulation was mixed to include powdered huntite at a dose of20 g/l.

The rheological and filtration properties of both fluids were measuredand are displayed in table 3.

                  TABLE 3    ______________________________________    PV         YP     6 rpm   3 rpm Gels  API FL    ______________________________________    Base    8.5    11.5   2     1     1/1   200 ml in 2    Solution                                min.    Base    Solution +            13.0   19.0   4     3     3/5   17.2 ml in 30    20 g/l                                  min.    Huntite    ______________________________________

The results show that the huntite addition has conferred an advantageousincrease in the YP and Gels of the fluid, and, more particularly, areduction in filtration rate by a factor of 174.

EXAMPLE 5

The viscosifying filtration control and acid solubility properties ofhuntite were compared to those of the conventional wellbore fluidmaterials bentonite and attapulgite (salt gel), when mixed into apotassium chloride brine based drilling fluid.

The following fluid formulations were mixed, (each formulation providing350 mls of fluid, value in gramms).

    ______________________________________    FORMULATION              A       B       C     D     E     F    ______________________________________    Water     295.5   295.0   294.7 289.1 288.0 287.5    KCl       102.2   102.3   102.2 100.2 99.9  99.7    Huntite   20.00                 40.00    Bentonite         20.00               40.00    Attapulgite               20.00             40.00    Hydroxyalkyl              6.00    6.00    6.00  6.00  6.00  6.00    Starch    ______________________________________

The Hydroxyalkyl starch is a conventional filtrate loss reducer forbrine based fluids.

The rheological properties of each fluid were tested both before (BHR)and after (AHR) heat ageing at 250° F. for 16 hours. The filtrationcontrol performance was tested after heat ageing. The results are shownin Table 4.

                  TABLE 4    ______________________________________                                    Gels    Addi-       6      3            10    tives       rpm    rpm    Gels10s                                    min  PV  YP  API FL    ______________________________________    A   BHR    20 g     9    8    9          7   14        AHR    Huntite  6    5    9     7    5   8   7.0    B   BHR    20 g     3    3    3          5   3        AHR    Benton-  2    2    2     2    2   3   8.5               ite    C   BHR    20 g     18   11   12         12  65        AHR    Attapul- 18   16   22    26   14  26  39.0               gite    D   BHR    40 g     26   25   24         12  37        AHR    Huntite  23   21   18    18   12  36  1O.5    E   BHR    40 g     4    3    3          4   6        AHR    Benton-  3    3    2     2    3   4   59.0               ite    F   BHR    40 g     71   42   46        AHR    Attapul- 60   42   61    78           58.0               gite    ______________________________________

The rheology results clearly show that Huntite is an effectiveviscosifier for potassium chloride brine based fluids. This is incontrast to bentonite which is known not to develop viscosity in saltsolutions (especially potassium chloride). Although attapulgite clay isa more effective viscosifier, huntite provides approximately a five foldreduction in filtration rate compared to attapulgite.

The filter cakes from fluids A, B and C were placed in 160 ml of 15% HClfor one hour. The acid insoluble residues were then measured byfiltration, drying, and weighting.

    ______________________________________    Results       Weight of Residue (g)    ______________________________________    A (Huntite)   0.001    B (Bentonite) 0.521    C (Attapulgite)                  1.350    ______________________________________

Clearly the huntite filter cake is soluble in 15% HCl in comparison tobentonite and attapulgite which leave substantial residues of insolubleclay. In a well, these residues would almost certainly reduce thepermeability of a formation and the well's productivity.

EXAMPLE 6 Synthetic Huntite Manufacturing Procedure

Method 1

A mixed magnesium chloride/calcium chloride brine was formulated using28 g CaCl₂ 2H₂ O and 115 g MgCl₂ 6H₂ O (all analytical reagents fromBDH) made up to 2 liter of brine using distilled water. A secondsolution was made containing 90 g of Na₂ CO₃ (analytical reagent ex BDH)in 1 liter of solution using distilled water.

200 ml of the magnesium/calcium chloride brine were placed into aHamilton Beach mixer cup and stirred on the mixer at low speed. 95 ml ofthe Na₂ CO₃ solution were slowly poured into the central vortex andimmediately a white precipitate was formed. The mixture was allowed tomix for a further 2 minutes to ensure complete mixing.

The resulting suspension was filtered and washed with distilled water.The white precipitate was dried and analysed by x-ray diffraction. Theresults showed diffraction peaks corresponding to spacings of 2.833 Å,2.888 Å, 1.972 Å the characteristic spacings for huntite.

Method 2

A slightly different manufacturing process was tried using a moreconcentrated brine solution 107.4 g CaCl₂ 2H₂ O and 445.0 g MgCl₂ 6H₂ Omade up to 1 liter with distilled water. The second solution was madecontaining 403.3 g of K₂ CO₃ in 1 liter of solution (with distilledwater). The second fluid was filtered to <μm to remove any particulatecontaminants.

175 ml of the calcium/magnesium chloride brine was placed in a HamiltonBeach mixer cup and stirred at low speed. 175 ml of the K₂ CO₃ solutionwas slowly added to the vortex. The white precipitate produced a veryviscous suspension which had to be transferred to a paddle mixer tocomplete mixing. As made the suspension had a PV of 11 cp, YP of 32lb/100 ft² and 6 and 3 readings of 22 and 16 respectively. Thesuspension was filtered and washed with distilled water. The whiteprecipitate was dried and analysed by x-ray diffraction. The resultsshowed diffraction peaks corresponding to spacings of 2.833 Å, 2.888 Åand 1.972 Å, the characteristic spacings for huntite.

We claim:
 1. A fluid selected from the group consisting of a fracturingfluid, a drilling fluid, a spotting fluid, a wellbore cement and aspacer fluid, said fluid comprising a brine and a liquid dispersion of aparticulate mixed divalent metal carbonate having a platy crystal form.2. The fluid of claim 1 in which the particulate mixed divalent metalcarbonate is a mixed alkaline earth metal carbonate.
 3. The fluid ofclaim 1 in which the particulate mixed divalent metal carbonate isselected from natural or synthetic huntite.
 4. The fluid of claim 2 inwhich the particulate mixed divalent metal carbonate is selected fromnatural or synthetic huntite.
 5. A wellbore fluid comprising an oilycontinuous liquid phase comprising a particulate mixed divalent metalcarbonate having a platy crystal form, the particulate mixed divalentmetal carbonate having been treated prior to use with an agent renderingthe surface of said divalent metal carbonate at least partiallyhydrophobic.
 6. The wellbore fluid of claim 5 in which the particulatemixed divalent metal carbonate is a mixed alkaline earth metalcarbonate.
 7. The wellbore fluid of claim 5 in which the particulatemixed divalent metal carbonate is selected from natural or synthetichuntite.
 8. In a method of well construction in which a wellbore fluidis employed, the improvement comprising using a wellbore fluidcomprising a liquid dispersion of a particulate mixed divalent metalcarbonate having a platy crystal form.
 9. The method of claim 8 whereinthe wellbore fluid comprises a mixed alkaline earth metal carbonate. 10.The method of claim 8 in which the particulate mixed divalent metalcarbonate is selected from natural or synthetic huntite.
 11. In a methodof well remediation in which a wellbore fluid is employed, theimprovement comprising using a wellbore fluid comprising a liquiddispersion of a particulate mixed divalent metal carbonate having aplaty crystal form.
 12. The method of claim 11 wherein the wellborefluid comprises a mixed alkaline earth metal carbonate.
 13. The methodof claim 11 in which the particulate mixed divalent metal carbonate isselected from natural or synthetic huntite.
 14. In a method of wellstimulation in which a wellbore fluid is employed, the improvementcomprising using a wellbore fluid comprising a liquid dispersion of aparticulate mixed divalent metal carbonate having a platy crystal form.15. The method of claim 14 wherein the wellbore fluid comprises a mixedalkaline earth metal carbonate.
 16. The method of claim 15 in which theparticulate mixed divalent metal carbonate is selected from natural orsynthetic huntite.
 17. The method of claim 8 wherein an acidic solutionis introduced to the well to dissolve residual mineral solids depositedby the method.
 18. The method of claim 11 wherein an acidic solution isintroduced to the well to dissolve residual mineral solids deposited bythe method.
 19. The method of claim 14 wherein an acidic solution isintroduced to the well to dissolve residual mineral solids deposited bythe method.
 20. An oil-based drilling fluid consisting essentially ofCaMg₃ (CO₃)₄, and an emulsifier.
 21. A fracturing fluid consistingessentially of CaMg₃ (CO₃)₄, and a compound selected from the groupconsisting of water-soluble polymers.
 22. The fluid according to claims20 or 21 wherein said CaMg₃ (CO₃)₄ is present in said fluid at aconcentration of between about 10 kg/m³ and about 50 kg/m³.
 23. Thefluid according to claims 20 or 21 wherein said CaMg₃ (CO₃)₄ is presentin said fluid at a concentration of between about 60 kg/m³ and about 200kg/m³.